INTRODUCTION TO ARTIFICIAL LIFT The Inflow Performance Relationship, or IPR, defines a well’s flowing
production potential:
q = PI × (Pavg - Pwf)
where q = production rate, B/D PI = productivity index, B/D/psi Pavg, or = average reservoir pressure, psi
Pwf = flowing bottomhole pressure, psi
(Figure 1) illustrates this relationship for a solution gas drive reservoir. Note that for a given average reservoir pressure and productivity index, Pwf determines the well’s production potential. The lower the flowing bottomhole pressure, the higher the production rate. The well’s maximum or absolute flow
potential would correspond to a Pwf of zero.
Figure 1
A well never actually attains its absolute flow potential, because in order for it to flow, Pwf must exceed the backpressure that the producing fluid exerts on the formation as it moves through the production system. This backpressure or bottomhole pressure has the following components:
Hydrostatic pressure of the producing fluid column
Friction pressure caused by fluid movement through the tubing, wellhead and surface equipment
Kinetic or potential losses due to diameter restrictions, pipe bends or elevation changes. In most production systems, these are not of the same magnitude as hydrostatic or friction pressures; in
others, however, they may be significant.
(1)
Artificial lift is a means of overcoming bottomhole pressure so that a well can produce at some desired rate, either by injecting gas into the producing fluid column to reduce its hydrostatic pressure,
or using a downhole pump to provide additional lift pressure downhole.
We tend to associate artificial lift with mature, depleted fields, where Pavg has declined such that the reservoir can no longer produce under its natural energy. But these methods are also used in younger
fields to increase production rates and improve project economics.
Artificial Lift Methods The two major categories of artificial lift are gas lift and pump-assisted lift. Plunger lift, which combines elements of both categories, is used primarily in gas and high-GOR wells to produce relatively small
volumes of liquid.
GAS LIFT Gas lift involves injecting high-pressure gas from the surface into the producing fluid column through
one or more subsurface valves set at predetermined depths (Figure 2: Gas lift system. Courtesy Weatherford International Ltd).
Figure 2
There are two main types of gas lift:
Continuous gas lift, where gas is injected in a constant, uninterrupted stream. This lowers the
overall density of the fluid column and reduces the hydrostatic component of the flowing bottomhole pressure. Thus, for a given average reservoir pressure and productivity index, the well is able to flow at a higher rate. This method is generally applied to wells with high
productivity indexes and high bottomhole pressures relative to their depths.
Intermittent gas lift, which is designed for lower-productivity wells. In this type of gas lift
installation, a volume of formation fluid accumulates inside the production tubing. A high-pressure “slug” of gas is then injected below the liquid, physically displacing it to the surface. As soon as the fluid is produced, gas injection is interrupted, and the cycle of liquid accumulation-
gas injection-liquid production is repeated.
The availability of gas and the costs for compression and injection are major considerations in planning a gas lift installation. Where these gas injection requirements can be satisfied, gas lift offers a flexible
means of optimizing production. It can be used in deviated or crooked wellbores, and in high-temperature environments that might adversely affect other lift methods, and it is conducive to maximizing lift efficiency in high-GOR wells. Wireline-retrievable gas lift valves can be pulled and
reinstalled without pulling the tubing, making it relatively easy and economical to modify the design.
On the negative side, gas lift system costs can adversely impact profitability if the source gas requires additional processing or surface compression. Lift efficiency can be reduced by corrosion and paraffin, which increase friction and backpressure. Tubing size and surface flowline length also affect system
efficiency. Another disadvantage of gas lift is its difficulty in fully depleting low-pressure, low-productivity wells. Also, the start-and-stop nature of intermittent gas lift may cause downhole pressure surges and lead to increased sand production.
PUMP-ASSISTED LIFT Downhole pumps are used to increase pressure at the bottom of the tubing string by an amount
sufficient to lift fluid to the surface. These pumps fall into two basic categories: positive displacement pumps and dynamic displacement pumps.
A positive displacement pump works by moving fluid from a suction chamber to a discharge chamber. The suction chamber volume increases as the discharge chamber volume decreases, causing fluid to
enter the suction chamber. As the cycle reverses, the suction volume decreases and the discharge volume increases, forcing the fluid to the discharge end of the pump. This basic operating principle applies to reciprocating rod pumps, hydraulic piston pumps and progressive cavity pumps (PCPs).
A dynamic displacement pump works by causing fluid to move from inlet to outlet under its own momentum, as is the case with a centrifugal pump. Dynamic displacement pumps commonly used in artificial lift include electrical submersible pumps (ESPs) and hydraulic jet pumps.
Reciprocating Rod Pump Systems A reciprocating rod pump system is made up of the following components (Figure 3: Rod pumping system. Courtesy Weatherford International Ltd):
Figure 3
A beam pumping unit, operated by an electric motor or gas engine.
A string of steel or fiberglass sucker rods that connect the beam pumping unit to the downhole pump.
A subsurface pump, which consists of a barrel, plunger and valve assembly that moves fluid
through the tubing and up to the surface.
Beam pumping is the most common and arguably the most recognizable artificial lift method. It can be
used for a wide range of production rates and operating conditions, and rod pump systems are relatively simple to operate and maintain. However, the volumetric efficiency (capacity) of a rod pump is lower in wells with high gas-liquid ratios, small tubing diameters or deep producing intervals. Surface
equipment requires a large amount of space compared with other lift methods, and its initial installation may involve relatively high capital costs.
Progressive Cavity Pump (PCP) Systems A progressive cavity pump consists of a spiral rotor that turns eccentrically inside an elastomer-lined stator (Figure 4: PCP system. Courtesy Weatherford International Ltd).
Figure 4
As the rotor turns, cavities between the threads of the pump rotor and stator move upward. The rotor is most often powered by rods connected to a motor on the surface, although some assemblies are
driven by subsurface electric motors.
Progressive cavity pumps are commonly used for dewatering coalbed methane gas wells, for production and injection applications in waterflood projects and for producing heavy or high-solids oil. They are versatile, generally very efficient, and excellent for handling fluids with high solids content.
However, because of the torsional stresses placed on rod strings and temperature limitations on the stator elastomers, they are not used in deeper wells.
Hydraulic Pump Systems Hydraulic pump systems use a power fluid—usually light oil or water—that is injected from the surface to operate a downhole pump. Multiple wells can be produced using a single surface power fluid installation (Figure 5: Hydraulic pumping system. Courtesy Weatherford International Ltd).
Figure 5
Downhole hydraulic pumps may be either of two types.
With a reciprocating hydraulic pump, the injected power fluid operates a downhole fluid engine,
which drives a piston to pump formation fluid and spent power fluid to the surface.
A jet pump is a type of hydraulic pump with no moving parts. Power fluid is injected into the pump body and into a small-diameter nozzle, where it becomes a low-pressure, high-velocity jet.
Formation fluid mixes with the power fluid, and then passes into an expanding-diameter diffuser. This reduces the velocity of the fluid mixture, while causing its pressure to increase to a level that is sufficient to lift it to the surface
Hydraulic pumps can be used at depths from 1000 to 17,000 feet and are capable of producing at rates from 100 to 10,000 B/D. They can be hydraulically circulated in and out of the well, thus eliminating the
need for wireline or rig operations to replace pumps and making this system adaptable to changing field conditions. Another advantage is that heavy, viscous fluids are easier to lift after mixing with the lighter power fluid.
Disadvantages of hydraulic pump systems include the potential fire hazards if oil is used as a power
fluid, the difficulty in pumping produced fluids with high solids content, the effects of gas on pump efficiency and the need for dual strings of tubing on some installations.
Electrical Submersible Pumps An electric submersible pumping (ESP) assembly consists of a downhole centrifugal pump driven by a submersible electric motor, which is connected to a power source at the surface (Figure 6: ESP system. Courtesy Weatherford International Ltd).
Figure 6
The pump and motor assembly, which may be several hundred feet long, is connected to the surface by an armored cable that provides electric power and control. On a cost-per-barrel basis, ESP systems
are among the most efficient and economical of lift methods. Fluid volumes ranging from 100 to 60,000 B/D, including high water-cut fluids, can be handled by ESP systems. These systems can be installed in high-temperature wells (above 350°F) using high-temperature motors and cables. The pumps can
be modified to lift corrosive fluids and sand. ESP systems can be used in high-angle and horizontal wells if placed in straight or vertical sections of the well.
ESP pumps can be damaged from “gas lock”. In wells producing high GOR fluids, a downhole gas separator must be installed. Another disadvantage is that ESP pumps have limited production ranges
determined by the number and type of pump stages; changing production rates requires either a pump change or installation of a variable-speed surface drive. The tubing must be pulled for pump repairs or replacement.
PLUNGER LIFT Plunger lift is the only artificial lift method that relies solely on the well’s natural energy to lift fluids. The
plunger, traveling inside the tubing, moves upward when the pressure of the gas below it is greater than the pressure of the liquid above it (Figure 7: Plunger lift system. Courtesy Weatherford International Ltd ) .
Figure 7
As the plunger travels to the surface, it creates a solid interface between the lifted gas below and
produced fluid above to maximize lifting energy. Any gas that bypasses the plunger during the lifting cycle flows up the production tubing and sweeps the area to minimize liquid fallback.
Plunger lift provides a cost-effective method of artificial lift that can be used to efficiently produce both gas wells with fluid loads and high GOR oil wells.
SELECTING AN ARTIFICIAL LIFT METHOD Artificial lift considerations should ideally be part of the well planning process. Future lift requirements will be based on the overall reservoir exploitation strategy, and will have a strong impact on the well
design.
Initial Screening Criteria Tables 1 and 2 below summarize some of the key factors that influence the selection of an artificial lift method.
Table 1
Reservoir and Hole Considerations in Selecting an Artificial Lift Method
(after Brown, 1980)
Reservoir Characteristics:
IPR A well’s inflow performance relationship defines its production potential
Liquid production rate The anticipated production rate is a controlling factor in selecting a lift method; positive displacement pumps are generally limited to rates
of 4000-6000 B/D.
Water cut High water cuts require a lift method that can move large volumes of fluid
Gas-liquid ratio A high GLR generally lowers the efficiency of pump-assisted lift
Viscosity Viscosities less than 10 cp are generally not a factor in selecting a lift method; high-viscosity fluids can cause difficulty, particularly in sucker rod pumping
Formation volume
factor
Ratio of reservoir volume to surface volume determines how much
total fluid must be lifted to achieve the desired surface production rate
Reservoir drive
mechanism
Depletion drive reservoirs: Late-stage production may require
pumping to produce low fluid volumes or injected water.
Water drive reservoirs : High water cuts may cause problems for lifting systems
Gas cap drive reservoirs : Increasing gas-liquid ratios may affect lift efficiency.
Other reservoir problems
Sand, paraffin, or scale can cause plugging and/or abrasion. Presence of H2S, CO2 or salt water can cause corrosion. Downhole emulsions can increase backpressure and reduce lifting efficiency.
High bottomhole temperatures can affect downhole equipment.
Hole Characteristics:
Well depth The well depth dictates how much surface energy is needed to move fluids to surface, and may place limits on sucker rods
and other equipment.
Completion type Completion and perforation skin factors affect inflow
performance.
Casing and tubing
sizes
Small-diameter casing limits the production tubing size and
constrains multiple options. Small-diameter tubing will limit production rates, but larger tubing may allow excessive fluid fallback.
Wellbore deviation Highly deviated wells may limit applications of beam pumping or PCP systems because of drag, compressive forces and
potential for rod and tubing wear.
Table 2
Surface and Field Operating Considerations in Selecting an Artificial Lift Method
(after Brown, 1980)
Surface Characteristics:
Flow rates Flow rates are governed by wellhead pressures and backpressures in surface production equipment (i.e.,
separators, chokes and flowlines).
Flowline size and length Flowline length and diameter determines wellhead pressure requirements and affects the overall performance of the production system.
Fluid contaminants Scale, paraffin or salt can increase the backpressure on a well.
Power sources The availability of electricity or natural gas governs the type of artificial lift selected. Diesel, propane or other sources may
also be considered.
Field location In offshore fields, the availability of platform space and placement of directional wells are primary considerations. In
onshore fields, such factors as noise limits, safety, environmental, pollution concerns, surface access and well spacing must be considered.
Climate and Physical environment
Affect the performance of surface equipment.
Field Operating Characteristics:
Long-range recovery plans Field conditions may change over time.
Pressure maintenance
operations
Water or gas injection may change the artificial lift
requirements for a field.
Enhanced oil recovery projects
EOR processes may change fluid properties and require changes in the artificial lift system.
Field automation If the surface control equipment will be electrically powered,
an electrically powered artificial lift system should be considered.
Availability of operating and
service personnel and support services
Some artificial lift systems are relatively low-maintenance;
others require regular monitoring and adjustment. Servicing requirements (e.g., workover rig versus wireline unit) should be considered. Familiarity of field personnel with equipment
should also be taken into account.
Clegg, Bucaram and Hein (1993), in a piece written for the SPE Distinguished Author Series, observe
that “selecting the proper artificial lift method is critical to the long-term profitability of most producing oil and gas wells.” They list 31attributes for comparing the eight most common artificial lift techniques (continuous and intermittent gas lift, beam pumping, progressing cavity pumping, hydraulic pumping,
electric submersible pumping, jet pumping and plunger lift), and provide practical guidelines for assessing each method’s capabilities. These are summarized as follows:
Design considerations and overall comparisons:
Capital cost
Downhole equipment
Efficiency
Flexibility
Operating costs
Reliability
Salvage value
System (total)
Miscellaneous [operating]
problems
Usage/outlook
Normal operating considerations:
Casing size limits
Depth limits
Intake capabilities
Noise level
Obtrusiveness
Prime mover flexibility
Surveillance
Testing
Time cycle and pump-off controllers application
Artificial lift considerations:
Corrosive/scale handling ability
Crooked/deviated holes
Multiple completions
Gas-handling ability
Offshore application
Paraffin-handling capability
Slim-hole completions
Solids/sand-handling ability
Temperature limitations
High-viscosity fluid handling
High-volume lift capabilities
Low-volume lift capabilities
Finally, Table 3 (from Weatherford International Ltd., 2005) summarizes typical characteristics and applications for each form of artificial lift. These are general guidelines, which vary among manufacturers and researchers. Each application needs to be evaluated on a well-by-well basis.
Table 3: Artificial Lift Methods—Characteristics and Areas of Application
(after Weatherford, 2005)
Operating
Parameters
Positive displacement pumps Dynamic displacement
pumps
Gas lift
Plung
er lift
Rod pump
PCP Hydraulic
Piston
ESP Hydraulic Jet
Typical Operating Depth
(TVD)
100 to 11000
ft
2000 to 4500 ft
7500 to
10000
ft
5000 to
10000
ft
5000 to 10000 ft
To 8000 ft
Maximum Operating
Depth (TVD)
16000 ft
6000 ft 17000 ft
15000 ft
15000 ft
15000 ft 20000 ft
Typical Operating
Volume
5 to 1500
BFPD
5 to 2200
BFPD
50 - 500
BFPD
100 to 30000
BFPD
300 - 4000
BFPD
100 - 10000
BFPD
1 - 5 BFPD
Maximum Operating
Volume
6000 BFPD
4500 BFPD
4000 BFPD
40000 BFPD
>15000
BFPD
30000 BFPD
200 BFPD
Typical Operating
Temperature
100 - 350 º F
[40-177
º C]
75 - 150 º F
[24-65
º C]
100 - 250 º F
[40-
120 º C]
100 - 250 º F
[40-
120 º C]
100 - 250 º F
[40-120 º
C]
120 º F
[50 º C]
Maximum Operating
temperature
550 º F
[288 º C]
250 º F
[120 º C]
500 º F
[260 º C]
400 º F
[205 º C]
500 º F
[260 º C]
400 º F
[205 º C]
500 º F
[260 º C]
Table 3: Artificial Lift Methods—Characteristics and Areas of Application
(after Weatherford, 2005)
Operating Paramete
rs
Positive displacement pumps Dynamic displacement
pumps
Gas lift
Plunger lift
Rod pump
PCP Hydraulic
Piston
ESP Hydraulic Jet
Typical
Wellbore Deviation
0 - 20
deg landed pump
N/A 0 - 20
deg landed pump
0 - 20
deg hole
angle
0 - 50
deg
N/A
Maximum Wellbore Deviation
0 - 90 deg
landed
pump
0 - 90 deg
< 15 deg/10
0 ft
0 - 90 deg
< 15 deg/10
0 ft
0 - 90 deg
0 - 90 deg
< 24 deg/10
0 ft
70 deg, short to medium
radius
80 deg
Corrosion handling
Good to
Excellent
Fair Good Good Excellent
Good to excellent
Excellent
Gas handling
Fair to good
Good Fair Fair Good Excellent Excellent
Solids handling
Fair to good
Excellent
Poor Fair Good Good Poor to Fair
Fluid gravity
> 8 º API
< 35 º API
> 8 º API
> 10 º API
> 8 º API
> 15 º API
GLR = 300
SCF/Bbl per 1000 ft
of depth
Servicing Workov
er or pulling
rig
Workov
er or pulling
rig
Hydrau
lic or wirelin
e
Workov
er or pulling
rig
Hydrau
lic or wirelin
e
Wireline
or workover
rig
Wellhe
ad catcher
or
wireline
Prime
mover
Gas or
electric
Gas or
electric
Multi-
cylinder or
electric
Electric
motor
Multi-
cylinder or
electric
Compres
sor
Well’s
natural energy
Offshore
applications
Limited Good Good Excelle
nt
Excelle
nt
Excellent N/A
System
efficiency
45% -
60%
40% -
70%
45% -
55%
35% -
60%
10% -
30%
10% -
30%
N/A
ECONOMICS OF ARTIFICIAL LIFT The features, benefits and limitations of one artificial lift method are relative to those of the other methods under consideration. Each method should be evaluated from the standpoint of comparative
economics. Brown (1980) lists six critical bases of comparison:
Initial capital cost
Monthly operating expense
Equipment life
Number of wells to be lifted
Surplus equipment availability
Expected producing life of well(s)
Capital cost considerations may favor one type of system over another, particularly when there is
significant uncertainty regarding well performance characteristics or reserve volumes. Gas lift is not likely to be a good option for a one or two-well system, for example—particularly if it requires adding surface compression facilities. For multiple wells, however, it may be a very economical choice.
Hydraulic pumping is likewise less costly when multiple wells are operated from a central injection facility.
Projected operating costs also figure into the selection of an artificial lift method. High gas prices will reduce the profitability of gas lift, particularly if it becomes necessary to purchase additional gas for
injection. But gas lift may be an attractive option in a remote field where there is no market for produced gas. In the same way, in places where electricity is not readily available, submersible pumps will be less attractive compared to gas lift or other forms of pump-assisted lift.
System reliability and easy access to repair equipment and services must also be considered.
Sometimes, the prevalence of a particular type of lift equipment in a given area will make that system more attractive.
If a well is expected to have a short producing life, capital and operating costs will play an important
role in the overall field economics and will affect the choice of an artificial lift system.
It is clear that for each well or field situation, a number of factors will affect the choice of artificial lift system. Equipment manufacturers can explain important advantages and disadvantages of different systems. Each type of artificial lift method has economic and operating limitations that can make it
more or less desirable when compared to others. Similarly, one artificial lift system will usually have at least one advantage over all others for a given set of operating conditions.